A principal thermal method of oil recovery from oil sands formations, for example, is steam-assisted gravity drainage (SAGO). In oil recovery via SAGD, steam at approximately 290° C. and suitable pressure (ranging for example from 70 to 150 bars) is injected from an injection well into the formation at depth to heat and liquefy the bitumen so that it flows downward into a recovery well situated several meters below the points of injection. The fluidized bitumen is brought to the surface along with injected steam/water at approximately 180-210° C. and 10 to 20 bars at the well head. Typical water/oil ratios at the well head range between approximately 2.0 to 4.0.
Oil is separated from the aqueous phase so that the oil product can be sent to the pipeline for downstream processing. The aqueous stream after the primary separation steps during oil/gas recovery operations is termed produced water. It typically contains some or all of the following: residual oily product, emulsified oily micelles, low levels of dissolved organic compounds, and dissolved inorganic salts along with microparticulates of sand and clay. The produced water is treated to remove oily residuals along with dissolved salts and the other substances before it can be recycled to the steam generators for re-injection.
Recycling of produced waters as herein exemplified in thermal heavy oil currently relies on separation of oily phases from a clarified aqueous phase. Separation processes typically include the use of flocculants, coagulants, micro-bubble flotation, inclined plate (lamella) separation, coalescing plate media, media bed filtration, organic membrane separation (reverse osmosis) and centrifugal separation arranged in various complete or partial combinations thereof.
None of these processes specifically include methods or techniques to insolubilize organic compounds that otherwise are dissolved in the produced water. Rather, current processes effect separation of only a fraction of soluble organic content through adsorption to and subsequent buoyancy of physically discrete and insoluble components of the produced water. These include free oil droplets, emulsified water-in-oil droplets, complex emulsion droplets, oil-wet solids of neutral-to-positive buoyancy, and high-specific-gravity (>1.0) oil wet solids comprised largely of microparticulates of mineral solids (such as sand and clay) that have been rendered positively buoyant through microbubble attachment. The existing philosophy of process design for produced water de-oiling in thermal heavy-oil operations and facilities relies on this buoyancy effect.
In practice, current process design for produced water de-oiling in thermal heavy oil recovery also results in removal of soluble organic compounds via physical adsorption onto and precipitation with potential sealants such as mineral silicates, carbonates, and phosphates that are removed during treatment steps that employ hydrated lime/magnesium oxide/sodium carbonate slurry contactors (“lime softeners” or “lime slurry softening reactors”).
However, such process elements are not included in some new construction designs that are built around falling film evaporation methods for provision of high quality boiler-water feed. Thus, the novel deoiling strategy being presented may also be further needed and particularly useful in such new construction.
There are no dimensioning criteria for practical deoiling methodology at laboratory scale beyond extraction of soluble organic compounds onto silica gel. However, silica gel treatment to remove soluble organic compounds from produced water has not been implemented, not only because the cost is too high for the results that can be achieved, but also in view of problems with handling and disposal of large waste amounts of oily silica gel.
The solubility of organic compounds in SAGD produced waters is generally at a maximal state at reservoir temperature (generally over 180° C. in thermal heavy oil recovery). As this water is brought to surface in the production process, it is typically cooled and de-pressured for storage in atmospheric tanks at temperatures of 80 to 90° C. and at atmospheric pressure. Under these circumstances, the solubility of both the organic compounds and some inorganic components like sulfides and silicates is reduced, and they approach some degree of super-saturation. This is commonly seen as a yellow to dark brown or black color in the waters.
The soluble and emulsified organic compounds in thermal heavy oil recovery operations are generally perceived to be predominately comprised of organic acids, which are negatively charged at near neutral pH. The stable reverse emulsion of oil-in-water that characterizes oil/gas produced water is thus considered to be anionically dispersed, or stabilized.
The ionic and polar character of these compounds, and their relatively high concentrations (on the order of 1000 ppm), interfere with the chemical and physical reactions commonly employed to prepare de-oiled produced water for reuse as boiler feed water. The process steps that are negatively influenced by the soluble organic compounds include precipitation softening, physical adsorption, ion exchange softening and media bed filtration.
The interference effects are not well-documented, due to the large variety of soluble organic chemicals involved; however, the chemical reactions of precipitation softening, physical adsorption, ion exchange softening and media bed filtration are known to work more efficiently and controllably in waters that contain no soluble organic compounds.